Much has been written about the deepwater Lower Tertiary Wilcox trend in the Gulf of Mexico, which spans hundreds of miles from Alaminos Canyon to Keathley Canyon to Walker Ridge (as well as adjacent areas). The estimated ultimate recoverable oil from these reservoirs is significant: 3 to 15 billion barrels. However, significant technical and reservoir challenges remain because of the water depth (typically greater than 5,000 ft), reservoir depth (typically greater than 20,000
to 30,000 ft below the mud line (BML)), and high pressures (greater than 20,000 psi bottomhole pressure (BHP)). Combining these issues with the thick, low permeability reservoir intervals (more than 1,000 ft thick in the tens of mD) requires new tools as well as new planning and optimization methods.
These new planning tools require system-wide (holistic) integration across multiple domains and completion software applications to produce a truly optimized completion. This type of integration is provided by an automated software workflow. Previous papers have provided details about the benefits derived from the automation of operations, engineering, and production workflows in general. Lower Tertiary Wilcox reservoirs were deemed good candidates by a major service
company to implement the automated workflow concept, given the reservoirs' low productivity index (PI), high-cost wells, high pressure/high temperature (HPHT) technical challenges, and production uncertainty.
This specific workflow seeks to optimize hydraulic fracture design within Lower Tertiary Wilcox reservoirs by stipulating the maximum net present value (NPV) that satisfies all well, completion, and reservoir constraints. Hydraulic fracture design is an example of what is largely a manual process that requires interaction with several software applications to obtain fracture geometry, production constraints, production sensitivity criteria, and NPV scenarios. When the goal is an optimized
fracture design, the process is especially arduous because it requires iterative interactions with reservoir simulators, nodal programs, economics models, well tubular design systems, and stimulation design tools to arrive at a suitable design.
Enabling coupled simulations technology, this fracture workflow provides a unique holistic combination of tools, which are linked to reflect the actual economic values.
Lower Tertiary Overview
The deepwater Lower Tertiary play is considered to be an extension of the established onshore Lower Tertiary Wilcox trend along the Gulf Coast in south Texas and Louisiana. The Lower Tertiary Wilcox play on land is primarily a gas play. In the deepwater Gulf of Mexico (GOM), the play targets the subsalt Paleogene formation, specifically Paleocene and Eocene, along the Sigsbee Escarpment in the Perdido and Mississippi Fan fold belts (Lewis et al. 2007). The trend is located 175 miles offshore GOM; it is approximately 80 miles wide by 300 miles long. Most of the activity in this trend is focused in Alaminos Canyon, Keathley Canyon, and Walker Ridge.
The trend is generally characterized by older sediments with lower porosities, ultra-deep water depths, and high BHPs. For this trend, water depths range from 4,000 to 10,000 ft; the target reservoirs depths have ranged from 25,000 to 35,000 ft. The reservoirs are thick, typically exceeding 1,000 ft gross, with high sand content (Halliburton 2011).
The BHPs of Lower Tertiary wells routinely exceed 20,000 psi; bottomhole temperatures (BHTs) range from 230° F to 300° F. Permeability and porosity values generally range from 1 to 50 mD, with an average of 10 mD; porosity values range from 14 to 20%, with an average of 17%. There is a wide range of PVT properties. The oil generally ranges from 22° to 41° API, with a low gas/oil ratio (GOR), and variable viscosity (Rains et al. 2007).
Hydraulic Fracturing in Western Siberia, Russia is a common practice that the need of stimulating wells in mature oil fields cannot be limited to non-complicated reservoirs. Wells requiring hydraulic fracturing with water zones either above or below is what we mean as reservoirs that require techniques that are out of the ordinary and day to day operations. A technique using dry solid material to contain the hydraulic fracture job within the zone of interest has been used in several wells and will be presented in this paper. The oil field Nivagalskoe which is located in Nizhnevartovsk area, Western Siberia, Russia is considered a mature oil field where due to the low value of the reservoir permeability, hydraulic fracturing these reservoirs require more than a skin bypass frac. Achieving a lengthier propped frac and descent net pressure increase is always a challenge on any hydraulic fracturing job execution but is always a must for the oil fields in the Nizhnevartovsk area. The challenge becomes when there are water zones close to the zone of interest to be stimulated via hydraulic fracturing. The objective is only not to design a job that will be limited in height by optimizing parameters commonly used in limiting frac geometry but to guarantee at best that the frac will not grow into the water zone. Several case histories will be presented where all cases the water cut was measured before and after the hydraulic fracturing job. The technique used and recommendations will be presented to optimize future jobs. All other options to limit frac geometry considered will also be presented.
Sayed, Mohammed Ali Ibrahim (Texas A&M University) | Nasr-El-Din, Hisham A. (Texas A&M University) | Almalki, Hassan (Qatar Petroleum) | Holt, Stuart Peter (Akzo Nobel Surface Chemistry LLC) | Zhou, Jian (Akzo Nobel Surface Chemistry LLC)
Acid treatments in high temperature deep wells drilled in carbonate reservoirs represent a challenge to the oil industry. The high temperature of deep wells requires a special formulation of emulsified acid that can be stable and effective at such high temperatures. At these high temperatures, both the reaction rate between acid and rock, and corrosion rate of tubulars are high. This fact makes protection of tubulars and reducing the reaction rate between rock and acid challenging. At temperatures above 200 ºF, there is a need to add more corrosion inhibitor and corrosion inhibitor intensifier, which increases the cost of the treatment too much.
A new emulsifier was developed and used to prepare emulsified acids that can be used in stimulating deep wells drilled in carbonate reservoirs. In the present paper, the rheology of the new acid is compared to the rheology of another system formulated by a commercial emulsifier that has been used extensively in the field. All emulsified acid systems were formulated at 0.7 acid volume fraction, and the final HCl concentration varied from 5 to 28 wt% HCl. The rheology measurements were conducted at temperatures up to 300 ºF for emulsifier concentration ranges from 0.5 to 2.0 vol%. The reaction between emulsified acid and rock was studied using a rotating disk apparatus at 230 ºF and rotation speeds up to 1,500 rpm. A core flood study was conducted in order to study the efficiency of the new emulsified acid to create wormhole, and increase the efficiency of the treatment, especially at a high temperature (300 ºF).
The results showed that the new emulsified acid system had higher thermal stability and higher viscosity than the old one. Also, the new emulsified acid system created deep wormholes at all injection rates covered (0.1 cm3/min up to 10 cm3/min), with no face dissolution encountered during acid injection. The reaction rate between emulsified acids formulated using the new emulsifier was measured using a rotating disk at 230 ºF. The dissolution rate varied between 2.57E-6 gmol/cm2.s at 100 rpm and 1.09E-5 gmol/cm2.s at 1500 rpm. The diffusion rate was measured for these emulsified acid systems and was found to be around 2.73E-7 cm2/s. From these results, the new emulsifier can be used in formulating emulsified acid systems that can be used effectively in stimulation of high temperature deep wells. This paper summarizes the results of testing the new emulsified system, and recommends its use for field application in deep carbonate reservoir.
Water shutoff using polymer gels has been practiced with success for long time. However, in certain cases, there is a need to acidize a well while isolating part of it using a gel treatment especially in long horizontal wells. The application of combined treatment is challenging and has resulted in a mixed outcome. The acid reacts with carbonate around the gel destroying the benefits of the gel treatment. Likewise, the application of the gel post an acidizing treatment is ineffective. The objective of this paper is to investigate the effectiveness of combining water shut-off and acidizing in one treatment in carbonate formations.
Core-flood testing was conducted to investigate the effectiveness of water shut-off gels before and after acidizing the core plug. Two scenarios were examined; the first one included pumping a cross-linked organic polymer gel to a carbonate core plug then followed by emulsified acid. In the second scenario, the core plug was acidized then the gel treatment was pumped. The gelling system consisted of polymer and dual set of delayed organic crosslinkers. The acid was 20 wt% emulsified HCl. CT scanning images were obtained before and after each step. The testing was performed at 200oF and 500 psi pore pressure.
The core flood experiments showed that when acid was applied after the gel treatment wormholes were created and dissolved the rock around the gel. On other hand, when the gel was applied after the acid, the gel was not able to withstand the differential pressures and allowed the flow of water because of the inability of the gel to plug the wormholes. It was demonstrated that the gel and acid treatments must be isolated from each other by mechanical means or deeper penetration of the gel.
Realistic laboratory simulation of fractures propped with sand, engineered ceramic proppants, and resin-coated proppants to determine the impact of temperature, stress, and stress cycling on proppant-pack structure and pack permeability is both difficult and expensive. Large, specialized testing equipment and long testing times are required, which can lead to high testing costs. This paper presents a new dynamic compression device (DCD) that permits rapid proppant-pack analysis to optimize proppant selection.
Understanding the mechanical and fluid dynamics of hard granular particle packs subjected to high closure stress and cyclic stress is important for understanding fracture conductivity and the impact of production operations. Few experimental studies have been reported where the compression of proppant with variable stress rates was used that also includes simultaneous direct visualization of the proppant structure.
The DCD imposes a controlled strain on the proppant pack while measuring the stress response, up to a compressive loading of 7,100 psi. Simultaneously, the liquid permeability and a detailed visualization of the proppant-pack structure are acquired. The stress loading and unloading process, performed in either a single or repeated (cycling) protocol, can be performed with precise measurement of the resulting system-level strain. Permeability results obtained using the DCD were comparable to those obtained using standard API linear conductivity determinations. Particle rearrangement by direct visualization during stress cycling was comparable to that predicted by use of a popular, commercial, three-dimensional particle-flow numeric simulator.
The DCD is a small, bench-top device that uses a small proppant sample. It has been demonstrated to be an efficient tool to experimentally determine the impact of closure stress, stress-change rate, proppant-packing properties, and the effect of multiple stress cycles on liquid permeability, while providing direct proppant-pack structure visualization. This new device enables rapid testing to determine the impact of expected downhole production conditions on proppant-pack permeability and permit selection of optimum proppant and proppant coatings.
Building an integrated subsurface model is one of the main goals of major oil and gas operators to guide the field development plans. All field data acquisitions from seismic, well logging, production and geomechanical monitoring to enhanced oil recovery operations can be affected by the accurate details incorporated in the subsurface model. Therefore, building a realistic integrated subsurface model in advance of the field development and associated design and operations is essential for a successful implementation of such projects. Furthermore, utilizing a more reliable model can in-turn provide the basis in the decision making process for control and remediation of formation damage.
One of the key identifier of the subsurface model is accurately predicting the hydraulic flow units. There are several models currently used in the prediction of these units based on the type of the data available. The predictions using these models are differing significantly due to the assumptions made in the derivations. Most of these assumptions do not adequately reflect realistic subsurface conditions increasing the need for better models to enhance the predictions.
A new approach has been developed in this study for predicting the petrophysical properties improving the reservoir characterization. Poiseuille flow equation and Darcy equation were coupled taking into consideration the irreducible water saturation in the pore network. The porous media was introduced as a domain containing bundle of tortuous capillary tubes with irreducible water lining the pore wall. A series of routine and special core analysis were performed on 17 Berea sandstone samples and the petrophysical properties were measured and XRD analysis was conducted. In addition, core permeabilities were predicted using a new permeability model and the results were compared to the measured permeability data. In building the petrophysical model, it was initially necessary to assume an ideal reservoir with 17 different layers. Afterwards, by iteration and calibration of the laboratory data, the more realistic number of hydraulic flow units was
The same model was also implemented to a Cotton Valley tight gas reservoir in Northern Louisiana in order to determine the flow units. A comparative study shows that the new model provides a better distribution of hydraulic flow units and prediction of the petrophysical properties. Using the new model provides a better match with the experimental data collected than the models currently used in the prediction of such parameters. The good agreement observed for both the Berea sandstone and Cotton Valley tight gas sand experimental data and the model predictions using the new permeability model show the wider range of applicability for various reservoir conditions.
A good surfactant-based acid should have the following properties: thermal stability, compatibility with cations, low viscosity in live acids but high viscosity in spent acids, ease to be removed by internal or external breakers, and no harm to the environment. Corrosion inhibitors must be added to the acid system to protect well tubulars and minimize the Fe contamination. The components of corrosion inhibitor usually contain short-chain alcohols (e.g. isopropyl alcohol) that can significantly affect the properties of surfactant-based acids. Therefore, corrosion inhibitor plays an important role in evaluating acid systems.
Two amine oxide surfactants (S and SW) were examined in this work. The composition of the surfactants was similar, but there was more 1,2 propanediol in surfactant SW. Three corrosion inhibitors (A, B, and C) were tested and all of them contained a certain amount of propargyl alcohol. However, there was a larger amount of isopropanol in corrosion inhibitor A, and more butanol in corrosion inhibitor B. A HPHT rheometer was used to measure the rheological properties (viscosity, G' and G'') of surfactant-based water system, live and spent acids from 75 to 300oF at 300 psi.
The results show that the addition of corrosion inhibitor to spent acid significantly reduced its elastic (G') and viscous modulus (G''). The maximum temperature that these two surfactants can be used was 220oF. Compared to surfactant-based acids made with corrosion inhibitor B or C, the acids with corrosion inhibitor A showed a much higher viscosity, but phase separation was observed after heating to 300oF. Although corrosion inhibitor B was compatible with surfactants, it adversely influenced the rheological properties of acids. If corrosion inhibitor C was used, the system with surfactant SW can be effectively used at temperatures above 150oF; whereas acids prepared with S1 can be efficiently applied at lower temperatures (<150oF). Cryo-TEM studies showed that corrosion inhibitors affected the rod-like micelle network, which caused the reduced apparent viscosity. Results of this work can be used to better select acid additives to maximize the performance of amine oxide-based acids.
Formation damage can occur through several different mechanisms ranging from scaling/precipitates to pore plugging by small particles. Polymer invasion into the reservoir pore spaces during drilling, completion or fracturing can be especially damaging and difficult to remediate. This has been previously reported to result from increases in the extensional viscosity that occurs as the polymer is extruded through the pores of the formation. This increase in extensional viscosity traps the polymer in the pore throat and creates a liquid crystalline type state that does not allow the polymer to relax and exit the pore space or allow remedial treatments such as acidizing to contact to polymer to break it down.
This paper will detail a laboratory investigation combining rheological studies of extensional viscosity of polymeric and viscoelastic surfactant fluids with formation damage testing performed on Berea sandstone cores. Using a laboratory rheometer, the shear rate applied to a sample will be increased exponentially, creating strong flows comparable to those experienced in flow through porous media. The type of polymers will be varied to include simple linear biopolymers (HEC), varying degrees of branched biopolymers (xanthan gum, scleroglucan gum), and hyper-branched synthetic polymers; fluids viscosified with polymers will then be compared with viscoelastic surfactant gels. A direct correlation between the rheological properties of the fluid to the formation damage potential of the fluid will be made. This correlation will allow for screening of fluids that will contact the reservoir through a much simpler rheological methodology as compared to the time consuming and highly variable formation damage tests via core flood experiments.
Wells completed in tight-gas sands often produce below expectations after fracture stimulation, with gel filtercake damage cited as a major cause of poor performance. These filtercakes have historically been viewed as immobile and insoluble in flowback water. However, recent field observations demonstrated conclusively that borate-crosslinked filtercakes delink and redissolve in flowback water. A fracture cleanup and chemistry simulator (FCCS) was used to discover and develop an appropriate rate law for the dissolution of gel filtercakes in flowback water. The simulator was validated by matching the observed gel content in the flowback waters from a fracturing treatment.
Previous work demonstrated that behavior of gel filtercakes in proppant packs from fracturing treatments was more complex than expected. Particularly interesting were recent observations of significant concentrations of gelling agent across several hundred barrels of flowback fluid from a fracturing treatment with good documentation. Ionic composition of the well returns was first matched with the FCCS. Matching of the gel recovery profile required discovery and development of a rate law for dissolution of gel filtercake by water inflowing from the fracture face. Potential rate laws using flow of water down the length of the fracture were not able to match the observed profile. Parametric studies were then conducted and showed a gel displacement regime and a dissolution regime for gel recovery, with the controlling regime dependent on gel phase saturation in the proppant pack. The gel phase saturation in the proppant pack should be 50% or less to be in the dissolution regime for efficient gel recovery.
The use of stabilized nanoparticle dispersions (NPDs) containing silica particles between 4??20 nm in diameter have been shown to be effective at removing skin damage associated with paraffin blocks, as well as polymer based treating and stimulation fluids. The arrangement of particles at the three phase interface
into structural arrays promotes lifting of the damage from the surface, stimulating the reservoir. Aqueous dispersions of nanoparticles used in conjunction with traditional remedial methods can effectively remove damage near the wellbore to be produced out of the well, instead of dissolution and potential displacement
of the damage further into the formation.
Many of the declining oil fields around the world owe a significant portion of their decreased production to formation damage. Usually, this damage is indicative of naturally occurring blocks, like paraffin, or as a result of intervention processes that occur over the lifetime of a well during drilling, stimulation, or intermittent remediation treatments. Eventually, the well can become damaged to the point it is no longer economically viable.
This paper will show lab and field results that indicate aqueous nanoparticle dispersions are a capable, and efficient additive for stimulating a damaged well by removal of skin from the surface of reservoir rock. This effect is due to a unique force called disjoining pressure, which causes particles at the nanometer??scale to
force themselves between organic matter and the substrate at the interface of the treating fluid. This force promotes the separation of an organic phase from a rock surface.